The background description provided herein is for the purpose of generally presenting the context of the disclosure. Work of the presently named inventors, to the extent the work is described in this background section, as well as aspects of the description that may not otherwise qualify as prior art at the time of filing, are neither expressly nor impliedly admitted as prior art against the present disclosure.
Productive reservoir systems of shale gas are composed of four types of porous media: inorganic matrix, organic matrix, natural fractures, and hydraulically induced fractures. Numerous organic flakes are sparsely scattered inside the inorganic matrix and are intersected by the natural fractures. Computational methods may be used to predict and enhance shale gas production from shale deposits, where permeability of the porous media is an important input parameter. Factors including a slippage effect and an adsorption affect permeability at nano and micro scales, which results in traditional computational methods that are either computationally too time consuming or require significant simplifications, thereby sacrificing accuracy and increasing errors.
Accounting for the slippage effect at high Knudsen (Kn) number is challenging in pore-scale simulations to accurately compute the permeability, therefore it has been treated using empirical correlation models to estimate the permeability of shale gas in shale deposits. Generally, permeability increases with the Kn number. The Kn number is defined here as the ratio of molecular mean free path to the representative pore size of shale rock. The Kn number is usually large in the organic matrix due to nano-pores. The molecular mean free path increases with decrease of pressure and thus permeability increases correspondingly during the gas production process.
Adsorption effect at a pore surface is also remarkable in shale gas flows due to nano-pores. The adsorption effect results in an adsorption thickness on the pore surface, which depends on the pressure and material of the pore surface. When the adsorption thickness is alike to the pore size of shale rock, the permeability significantly decreases due to a reduction of effective passage area. In contrast, the slippage effect at high Kn increases the permeability and also depends on the pressure as discussed above. Consequently, the prediction of permeability variation with pressure is very difficult due to the slippage and adsorption effects. Traditional experimental scheme to measure the flow speed to determine the permeability of shale gas requires considerable time and is usually subjected to noises and errors due to low flow speed. Transient pressure decay is measured in the current pulse-decay experimental scheme and applied in a mathematical model to inversely predict the permeability of the shale rock sample. But, this scheme is not convincible because of being dependent on an empirical correction term at high Kn obtained with significant simplifications.